To produce oil or gas from a reservoir, a well is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.
Drilling
The well is created by drilling a hole into the earth (or seabed) with a drilling rig that rotates a drill string with a drilling bit attached to the downward end. Usually the borehole is anywhere between about 5 inches (13 cm) to about 36 inches (91 cm) in diameter. As upper portions are cased or lined, progressively smaller drilling strings and bits must be used to pass through the uphole casings or liners, which steps the borehole down to progressively smaller diameters.
While drilling an oil or gas well, a drilling fluid is circulated downhole through a drillpipe to a drill bit at the downhole end, out through the drill bit into the wellbore, and then back uphole to the surface through the annular path between the tubular drillpipe and the borehole. The purpose of the drilling fluid is to lubricate the drill string, maintain hydrostatic pressure in the wellbore, and carry rock cuttings out from the wellbore.
The drilling fluid can be water-based or oil-based. Oil-based fluids tend to have better lubricating properties than water-based fluids, nevertheless, other factors can mitigate in favor of using a water-based drilling fluid.
Both the dissolved solids and the undissolved solids can be chosen to help increase the density of the drilling fluid. An example of an undissolved weighting agent is barite (barium sulfate). The density of a drilling mud can be much higher than that of typical seawater or even higher than high-density brines due to the presence of suspended solids. The weight of pure water is about 8.3 ppg (990 g/l), whereas mud weights can range from about 6 ppg (720 g/l) to about 22 ppg (2600 g/l).
In addition, the drilling fluid may be viscosified to help suspend and carry rock cuttings out from the wellbore. Rock cuttings can range in size from silt-sized particles to chunks measured in centimeters. Carrying capacity refers to the ability of a circulating drilling fluid to transport rock cuttings out of a wellbore. Other terms for carrying capacity include hole-cleaning capacity and cuttings lifting.
Cementing, Completion, and Production
After a portion of the wellbore is drilled, sections of pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.
Primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass as a sheath to thereby attach the string of pipe to the walls of the wellbore and seal the annulus. The main objectives of primary cementing operations include zonal isolation to prevent migration of fluids in the annulus, support for the casing or liner string, and protection of the casing string from corrosive formation fluids. Subsequent secondary cementing operations may also be performed. Secondary or remedial cementing operations are performed to repair primary-cementing problems or to treat conditions arising after the wellbore has been constructed.
Completion is the process of making a well ready for production or injection. This principally involves preparing a zone of the wellbore to the required specifications, running in the production tubing and associated downhole equipment, as well as perforating and stimulating as required.
Oil or gas in the subterranean formation may be produced by driving fluid into the well using, for example, a pressure gradient that exists between the formation and the wellbore, the force of gravity, displacement of the fluid using a pump or the force of another fluid injected into the well or an adjacent well. The production of fluid in the formation may be increased by various stimulation techniques, such as hydraulically fracturing the formation. That is, a viscous fracturing fluid may be pumped down the casing to the formation at a rate and a pressure sufficient to form fractures that extend into the formation, providing additional pathways through which the oil or gas can flow to the well.
Fluid Loss and Lost Circulation
In general, fluid loss refers to the undesirable leakage of a fluid phase of any type of drilling or treatment fluid into the permeable matrix of a subterranean formation. Fluids used in drilling, completion, or servicing of a wellbore can be lost to a subterranean formation while circulating the fluids in the wellbore. In particular, the fluids may enter the subterranean formation via depleted zones, zones of relatively low pressure, lost circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth.
During drilling, lost circulation refers to the reduced or total absence of fluid flow up the annulus when fluid is pumped through the drill string. As used herein, this reduction of flow can generally be classified as seepage of less than about 10 bbl/hr (about 1.2 m3/hr), partial lost returns but still some returns, and total lost returns where no fluid returns up the annulus.
In the case of total lost returns, the wellbore may not remain full of fluid even if the pumps are turned off. If the hole does not remain full of fluid, the vertical height of the fluid column is reduced and the pressure exerted on the open formations is reduced. This in turn can result in another zone flowing into the wellbore, while the loss zone is taking mud. It may even result in a catastrophic loss of well control. The loss of fluid to a formation costs the drilling fluid and slows the drilling rate.
Lost Circulation Control
In cases of high fluid loss, lost circulation control involving various plugging materials such as walnut hulls, mica, and cellophane have been used to prevent or lessen the loss of fluids from wellbores. Such non-degradable materials are suitable for use in non-producing zones, however, in producing zones the disadvantages of such materials include the potential for damage to the subterranean formations as a result of the inability to remove the plugging materials.
Damage to Permeability
In well treatments using viscous fluids, the material for increasing the viscosity of the fluid can damage the permeability of the subterranean formation.
After application of a lost circulation fluid or treatment, it may be desirable to restore permeability of the producing zone. If the formation permeability of the desired producing zone is not restored, production levels from the formation can be significantly lower. Any material in the zone resulting from a lost circulation control treatment must be removed to restore the formation's permeability, preferably to at least its original level.
Carbonate Formations and Lost Circulation
Lost circulation has been and still one of the major drilling related issues causing non-productive time (“NPT”) on a drilling rig. So far, particulate based and chemistry based lost circulation materials (“LCMs”) have been reportedly used quite successfully for combating drilling fluid losses while drilling into formations such as sandstone or shale.
Drilling carbonate formations is altogether a different scenario, however. Carbonate formations may be naturally highly fractured, vugular, or fragile. Carbonate formations tend to have complex porosity and permeability variations with irregular fluid flow paths. It has been reported that carbonate formations tend to break, just when the bit hits the formation while drilling. Lost circulation, even complete loss of circulation, may be encountered when drilling into these types of carbonate formations. This problem can be a rate determining step for drilling operations in such formations.
Controlling lost circulations in vugular or heavily fractured carbonate formations with particulate lost circulation material (“LCM”) has not found much success till date. Contemporary practices in an effort to manage lost circulations when drilling into such carbonate formations include the use of highly viscous fluids or gunks. Many a times, however, these contemporary solutions would not find success as anticipated. As a last resort, mud cap drilling methods can be used, in which a high-viscous, low-cost fluid is pumped down the annulus that is lost into the formation following by another fluid system is pumped through drill string helping to drill ahead. Overall, however, to successfully drill ahead in carbonate highly vugular or heavily fractured carbonate formations without much NPT, controlling lost circulation would be an important part of a drilling plan.